Producing a hydrocarbon fluid wherein using a fiber optical distributed acoustic sensing (das) assembly

ABSTRACT

A method of producing a hydrocarbon fluid from a subsurface formation, wherein use is made of a directionally sensitive Distributed Acoustic Sensing (DAS) fiber optical assembly having adjacent lengths of optical fiber (A,B) with different directional acoustic sensitivities, which are used to detect the direction (α) of acoustic signals relative to the lengths of optical fiber (A,B).

CROSS REFERENCE TO EARLIER APPLICATION

This is a divisional application of U.S. application Ser. No. 13/996431,filed Jun. 30, 2013, which is incorporated herein by reference, andwhich is a national stage application of PCT/EP2011/073471, filed Dec.20, 2011, which claims priority from European application 11174781.2,filed Jul. 21, 2011, and European application 10196253.8, filed Dec. 21,2010, which is incorporated herein by reference.

FIELD OF THE INVENTION

The invention relates to fiber optic devices and in particular to afiber optical Distributed Acoustic Sensing (DAS) assembly adapted tosense the direction of acoustic signals that are travelling at an angleor substantially perpendicular to the DAS assembly.

BACKGROUND OF THE INVENTION

Various attempts have been made to provide sensing capabilities in thecontext of petroleum exploration, production, and monitoring, withvarying degrees of success. Recently, these attempts have included theuse of fiber optic cables to detect acoustic energy. Because the cablestypically comprise optically conducting fiber containing a plurality ofbackscattering inhomogeneities along the length of the fiber, suchsystems allow the distributed measurement of optical path length changesalong an optical fiber by measuring backscattered light from a laserpulse input into the fiber. Because they allow distributed sensing, suchsystems are often referred to as “Distributed Acoustic Sensing” or “DAS”systems. One use of DAS systems is in seismic applications, in whichseismic sources at known locations transmit acoustic signals into theformation, and/or passive seismic sources emit acoustic energy. Thesignals are received at seismic sensors after passing through and/orreflecting through the formation. The received signals can be processedto give information about the formation through which they passed. Thistechnology can be used to record a variety of seismic information.Another application range is concerning in-well applications, such asflow- and event detection.

Known DAS assemblies with optical fibers having different acousticsensitivities are disclosed in UK patent GB 2197953 and U.S. Pat. Nos.4,297,887 and 4,405,198. The DAS assembly known from U.S. Pat. No.4,405,198 comprises twisted optical fibers that may be arranged inparallel with other like fibers and axes twisted at different pitchesthereby enabling detection of sound waves over a range of frequenciesand their angles of incidence.

While there exists a variety of commercially available DAS systems thathave varying sensitivity, dynamic range, spatial resolution, linearity,etc., all of these systems are primarily sensitive to axial strain asthe angle between direction of travel of the acoustic signal and thefiber axis approaches 90°, DAS cables become much less sensitive to thesignal and may even fail to detect it.

Thus, it is desirable to provide an improved cable that is moresensitive to signals travelling normal to its axis and enablesdistinguishing this radial strain from the axial strain. Such signalstravelling normal to the longitudinal axis of the fiber may sometimes bereferred to as “broadside” signals and result in radial strain on thefiber. Sensitivity to broadside waves is particularly important forseismic or microseismic applications, with cables on the surface ordownhole.

Furthermore, there is a need to provide an improved method for detectingthe direction of acoustic signals relative to a longitudinal axis offiber optical DAS assembly.

SUMMARY OF THE INVENTION

The invention provides a method of producing a hydrocarbon fluid from asubsurface formation through a well, wherein use is made of adirectionally sensitive Distributed Acoustic Sensing (DAS) fiber opticalassembly comprising at least two substantially parallel lengths ofadjacent optical fibers with different directional acousticsensitivities in the well, wherein the at least two lengths of adjacentoptical fiber comprise a first length of optical fiber with a firstratio between its axial and radial acoustic sensitivity and the secondlength of optical fiber with a second ratio between its axial and radialacoustic sensitivity; and providing an algorithm for detecting adirection of propagation of an acoustic signal relative to alongitudinal axis of the first and second lengths of optical fiber onthe basis of a comparison of differences of radial and axial strain inthe first and second lengths of optical fiber resulting from theacoustic signal.

In one or more embodiments, the directionally sensitive DAS fiberoptical assembly may be used to monitor and/or control features of asubsurface formation and/or subsurface flux of fluid through a formationinto a well and/or fluid flux through a subsurface well assembly.

In one or more embodiments, the directionally sensitive DAS assembly maybe used to monitor, manage and/or control the flux of hydrocarbon fluidsthrough a subsurface formation and/or through a hydrocarbon fluidproduction well assembly.

These and other features, embodiments and advantages of the DistributedAcoustic Sensing(DAS) fiber optical assembly and method according to theinvention are described in the accompanying claims, abstract and thefollowing detailed description of non-limiting embodiments depicted inthe accompanying drawings, in which description reference numerals areused which refer to corresponding reference numerals that are depictedin the drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more detailed understanding of the invention, reference is made tothe accompanying drawings wherein:

FIG. 1 is a schematic view of a directionally sensitive fiber opticalDAS assembly in a well and a graphical and physical explanation of itsdirectional sensitivity; and

FIGS. 2 and 3 are plots showing exemplary ratios between the axial andradial strain and associated axial and radial acoustic sensitivity foracrylate- and copper-coated optical fibers, respectively.

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT

There is provided a directionally sensitive Distributed Acoustic Sensing(DAS) fiber optical assembly comprising at least two substantiallyparallel lengths of adjacent optical fiber with different directionalacoustic sensitivities, wherein the at least two lengths of adjacentoptical fiber comprise a first length of optical fiber A with a firstratio between its axial and radial acoustic sensitivity and a secondlength of optical fiber B with a second ratio between its axial andradial acoustic sensitivity; and

an algorithm is provided for detecting a direction of propagation of anacoustic signal relative to a longitudinal axis of the first and secondlengths of optical fiber on the basis of a comparison of differences ofradial and axial strain in the first and second lengths of optical fiberresulting from the acoustic signal.

The first ratio may be between 300 and 1000 and the second ration may bebetween 100 and 300.

The at least two lengths of adjacent optical fiber may comprise a firstlength of coated fiber having a first coating, such as an acrylatecoating, and a second length of coated fiber having a second coating,such as a copper coating, wherein the first and second coatings areselected such that the Young's Modulus or Poisson's ratio of the firstlength of coated fiber is less than the Young's Modulus or Poisson'sratio of the second length of coated fiber.

Alternatively or additionally the at least two lengths of adjacentoptical fiber comprise a first length of optical fiber with a firstdiameter and a second length of optical fiber with a second diameter.

Optionally, the at least two lengths of adjacent optical fiber compriseadjacent sections of a single fiber optic cable having a coating with atleast one property that varies along the length of the cable, the atleast one property being selected from the group consisting of Poisson'sratio and Young's modulus.

There is furthermore provided a directionally sensitive DistributedAcoustic Sensing (DAS) method, which comprises providing a (DAS) fiberoptical assembly comprising at least two substantially parallel lengthsof adjacent optical fibers with different directional acousticsensitivities, wherein the at least two lengths of adjacent opticalfiber comprise a first length of optical fiber with a first ratiobetween its axial and radial acoustic sensitivity and the second lengthof optical fiber with a second ratio between its axial and radialacoustic sensitivity; and

deploying an algorithm for detecting a direction of propagation of anacoustic signal relative to a longitudinal axis of the first and secondlengths of optical fiber on the basis of a comparison of differences ofradial and axial strain in the first and second lengths of optical fiberresulting from the acoustic signal.

The directionally sensitive DAS method described herein may be used tomonitor and/or control features of a subsurface formation and/orsubsurface flux of fluid through a formation into a well and/or fluidflux through a subsurface well assembly.

Moreover, the directionally sensitive DAS method may be used to monitor,manage and/or control the flux of hydrocarbon fluids through asubsurface formation and/or through a hydrocarbon fluid production wellassembly. The disclosure further provides a method of producing ahydrocarbon fluid from a subsurface formation wherein use is made of thedirectionally sensitive DAS assembly and/or the directionally sensitiveDAS method described herein.

Although fiber optical DAS cables are better at detecting axial strain,they can detect radial strain as a result of the Poisson effect orstrain-optic effect. When radial strain is applied to the fiber, thefiber expands in the axial direction or directly induces a radial strainon the fiber leading to a change in refractive index. The amount ofaxial strain that is induced by the radial strain is determined by thePoisson ratio, which is a material property of the optical fiber. Formost materials, the Poisson's ratio is between 0 and 0.5 (although someexotic materials can have negative values). The amount of refractiveindex change that is induced by radial strain is determined by thestrain-optic coefficients.

As a result of the magnitude of the various strain transfer effects,seismic data recorded using a DAS system will contain signals resultingprimarily from waves that are in line with the fiber and smaller signalsresulting from waves that are incident perpendicular to the fiber. Inthe case of Poisson's ratio effects, a broadside seismic wave attemptsto induce the same axial strain at every point on the fiber. Bysymmetry, the axial particle motion and hence the movement of impuritiesthat lead to detection in a DAS system, is zero or near-zero. Hence,radial strain transfer in a uniform situation is mainly governed bystrain-optic effects.

In some embodiments, the present invention seeks to resolve the paralleland perpendicular components using a novel fiber optic cable deploymentand post-processing scheme effectively generating distributedmulti-component seismic data. The degree to which radial strain isconverted to axial strain in the fiber can be tailored by coating thefiber with materials that have a larger or smaller Young's Modulus orPoisson's ratio.

Similarly, by axially varying other material properties, such as theYoung's modulus (stiffness) of the fiber, along the length of the fiber,it may be possible to induce axial strain modulation in the fiber usinga broadside wave. Other properties of the fiber, coating or sheathmaterial can be varied, and may be selected depending on the elasticity,isotropy, and homogeneity of the material(s).

In preferred embodiments, the heterogeneous fiber with varying Poissonratio and/or Young's modulus is suspended in a fluid, so that it is notconstrained to deform with the formation. The fluid could be water oranother incompressible fluid.

The embodiments described herein can be used advantageously in alone orin combination with each other and/or with other fiber optic concepts.Similarly, the variations described with respect to fiber coatings canbe applied using the same principles to the cable jacket includingchanging properties of a possible gel in the cable.

The DAS methods and DAS assemblies described herein can likewise be usedto detect microseisms and the data collected using the presentinvention, including broadside wave signals, can be used in microseismiclocalization. In these embodiments, the data are used to generatecoordinates of a microseism.

In still other applications, the DAS methods and DAS assembliesdescribed herein can be used to measure arrival times of acousticsignals and in particular broadside acoustic waves. Arrival times giveinformation about the formation and can be used in various seismictechniques.

In still other applications, ability of the DAS assemblies to detectbroadside waves and axial waves distinguishably can be used in variousDAS applications, including but not limited to intruder detection,monitoring of traffic, pipelines, or other environments, and monitoringof various conditions in a borehole, including fluid inflow.

FIG. 1 is a schematic view of a well in which a directionally sensitivefiber optical DAS assembly according to the invention is arranged.

The DAS assembly shown in FIG. 1 comprises two adjacent lengths ofoptical fiber A and B with different directional acoustic sensitivities.The two adjacent lengths of optical fiber A and B may be differentfibers that are suspended substantially parallel to each other in thewell 30, or may be interconnected by a fiber optical connection 31, ormay be different parts of a single U-shaped optical fiber of which thedifferent parts have different directional sensitivities. To createmulti-directional sensitivity, both along cable (axial) andperpendicular to cable (radial) acoustic/strain amplitudes ε_(a) andε_(r) may be detected and processed as shown in Equations (1) and (2).

In FIG. 1 an acoustic wavefront 33 is travelling at an angle α towardsadjacent channels X and Y of the lengths of optical fiber A and B andthereby generate an axial strain ε_(a) and a radial strain ε_(r) inthese lengths of optical fiber A and B, which axial and radial strainsε_(a) and ε_(r) detected by analyzing differences in reflections ofoptical signals transmitted through the lengths of optical fiber A andB, which reflections stem, on the basis of a time of flight of analysis,from channels X and Y.

This can be used: as a “2D” geophone that measures the angle α betweenthe direction of the wavefront 33 and a longitudinal axis 34 of the well30, or to determine the angle of incidence α (directivity) of theacoustic wave front 33 relative to the longitudinal axis 34 of the well30. This requires measuring by at least two lengths of fiber A and Bsimultaneously. The axial/radial sensitivity ratio of these two fibersshould be different. The fibers should be in the same acoustic inputwavefront 33 (i.e. close to each other, same coupling, etc.), be itdifferent fibers in one cable assembly or multiple cable assemblies nextto each other.

To control the ratio between axial and radial sensitivity ε_(a) andε_(r) of the lengths A and B of optical fiber these lengths may becoated with different coatings. For example, the first length of opticalfiber A may be coated with standard acrylate coating 35 whilst thesecond length of optical fiber B may be coated with a with a coppercoating 36. The difference in Young's Modulus (and to a lower degree:Poisson's ratio), change the degree to which physical length and opticalpath length (speed of light) vary. This leads to a different ratiobetween axial and radial sensitivity resulting from different axial andradial strain ε_(a) and ε_(r) measured at channels X and Y and otherchannels along the lengths of optical fiber A and B.

Depending on the acoustical environment, exemplary FIGS. 2 and 3 showthat the ratio between the axial and radial strain and associated axialand radial acoustic sensitivity of the acrylate coated length of opticalfiber A is about 551:1 and that the ratio between the axial and radialstrain and associated axial and radial acoustic sensitivity of thecopper coated length of optical fiber B is about 138:1. Differentalternative coatings 35, 36 may be used, provided that these alternativecoatings 35,36 result in different axial and radial acousticsensitivities of the two lengths of optical fiber A and B, wherein theratio of the axial and radial acoustic sensitivities of the first lengthof optical fiber A is preferably in the range between 300 and 1000 andthe ratio between the axial and radial acoustic sensitivity of thesecond length of optical fiber B is preferably in the range between 100and 300.

Equations (1) and (2) show how the directional sensitivities ΔΦ_(A)^(DAS) and ΔΦ_(B) ^(DAS) are derived.

ΔΦ_(A) ^(DAS) =f(ε_(axial) ^(outside))+g(ε_(radical) ^(outside))   (1)

ΔΦ_(B) ^(DAS) =h(ε_(axial) ^(outside))+k(ε_(radial) ^(outside))   (2)

where the axial and radial strains ε_(a) and ε_(r), respectively, aremeasured at the outside of channels X and Y of the adjacent lengths ofoptical fiber A and B. When the ratio of the axial to radial strain isknown for each cable are known, Equations 1 and 2 can be solved for thestrain variables.

It will be understood that the control of axial/radial strain ratios maynot only be achieved by providing the adjacent lengths of optical fiberwith different fiber coatings, such as acrylate and copper, but can alsobe achieved by providing the adjacent lengths of optical cable A and Bwith different properties, such as different Young's Modulus of anyfiber layers, different diameters of fiber (layers), differentproperties of fillings (like gel) used in cable assemblies, for exampledifferent viscosity and Young's Modulus of such gels, differentmaterials and thicknesses used for metal tubes in cable assembliesand/or alternating properties along the lengths of optical fiber A and Bof the fiber optical DAS assembly according to the invention.

While preferred embodiments have been disclosed and described, it willbe understood that various modifications can be made thereto.

That which is claimed is: 1-13. (canceled)
 14. A method of producing ahydrocarbon fluid from a subsurface formation through a well, whereinuse is made of a directionally sensitive Distributed Acoustic Sensing(DAS) fiber optical assembly comprising at least two substantiallyparallel lengths of adjacent optical fibers with different directionalacoustic sensitivities in the well, wherein the at least two lengths ofadjacent optical fiber comprise a first length of optical fiber with afirst ratio between its axial and radial acoustic sensitivity and thesecond length of optical fiber with a second ratio between its axial andradial acoustic sensitivity; and providing an algorithm for detecting adirection of propagation of an acoustic signal relative to alongitudinal axis of the first and second lengths of optical fiber onthe basis of a comparison of differences of radial and axial strain inthe first and second lengths of optical fiber resulting from theacoustic signal.
 15. The method of claim 14, wherein algorithm comprisesthe formula's:ΔΦ_(A) ^(DAS) =f(ε_(axial) ^(outside))+g(ε_(radial) ^(outside))ΔΦ_(B) ^(DAS) =h(ε_(axial) ^(outside))+k(ε_(radial) ^(outside)) fordetermining the axial and radial strains ε_(axial) and ε_(radial),respectively, incident at the outside of channels X and Y of theadjacent substantially straight lengths of optical fiber A and B bymeasuring the signals ΔΦ_(A) ^(DAS) and ΔΦ_(B) ^(DAS) of the first andsecond lengths of optical fiber A and B and wherein the factors f, g, hand k are empirically obtained factors relating to the ratio ofsensitivity of the lengths of optical fiber A and B to axial and radialstrain ε_(axial) and ε_(radial), respectively.
 16. The method of claim14, wherein the first ratio is between 300 and 1000 and the second ratiois between 100 and
 300. 17. The method of claim 14, wherein the at leasttwo lengths of adjacent optical fiber comprise a first length of coatedfiber having a first coating and a second length of coated fiber havinga second coating, wherein the first and second coatings are selectedsuch that the Young's Modulus and Poisson's ratio of the first length ofcoated fiber is less than the Young's Modulus and Poisson's ratio of thesecond length of coated fiber.
 18. The method of claims 14, wherein thefirst length of optical fiber has an acrylate coating and the secondlength of optical fiber has a copper coating.
 19. The method of claim14, wherein the at least two lengths of adjacent optical fiber comprisea first length of optical fiber with a first diameter and a secondlength of optical fiber with a second diameter.
 20. The method of claim14, wherein the at least two lengths of adjacent optical fiber compriseadjacent sections of a single fiber optic cable having a coating with atleast one property that varies along the length of the cable, the atleast one property being selected from the group consisting of Poisson'sratio and Young's modulus.
 21. The method of claim 14, wherein theadjacent lengths of optical cable with different directional acousticproperties comprise at least one of the following features: adjacentlengths of optical cable having a different Young's Modulus; adjacentlengths of optical cable with different diameters; adjacent lengths ofoptical cable comprising fiber layers having a different Young'sModulus; adjacent lengths of optical cable comprising fiber layershaving different inner and/or outer diameters; adjacent lengths ofoptical cable comprising annular fiber layers filled with fillings, suchas gels having different properties, such as different viscositiesand/or Young's Modulus; adjacent lengths of optical cable surrounded bymetal tubes having a different Young's Modulus, different materialcompositions, and/or thicknesses; adjacent lengths of optical cablehaving varying and/or alternating acoustic properties along the lengththereof.
 22. The method of claim 14, wherein the directionally sensitiveDAS fiber optical assembly is used to monitor and/or control features ofthe subsurface formation.
 23. The method of claim 22, wherein the wellis a subsurface well in the subsurface formation.
 24. The method ofclaim 14, wherein the directionally sensitive DAS fiber optical assemblyis used to monitor and/or control subsurface flux of fluid through thesubsurface formation into the well.
 25. The method of claim 14, whereinthe directionally sensitive DAS fiber optical assembly is used tomonitor and/or control fluid flux through the well.
 26. The method ofclaim 14, wherein the well is a subsurface well.
 27. The methodaccording to claim 14, wherein the directionally sensitive DAS fiberoptical assembly is used to monitor, manage and/or control the flux ofthe hydrocarbon fluids through the subsurface formation.
 28. The methodaccording to claim 27, wherein the well is a subsurface well in thesubsurface formation.
 29. The method according to claim 14, wherein thedirectionally sensitive DAS fiber optical assembly is used to monitor,manage and/or control the flux of the hydrocarbon fluids through ahydrocarbon fluid production well assembly.
 30. The method according toclaim 14, wherein the directionally sensitive DAS fiber optical assemblyis used to monitor, manage and/or control the flux of the hydrocarbonfluids through the well.